US7481275B2 - Plant and a method for increased oil recovery - Google Patents

Plant and a method for increased oil recovery Download PDF

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US7481275B2
US7481275B2 US10/538,418 US53841805A US7481275B2 US 7481275 B2 US7481275 B2 US 7481275B2 US 53841805 A US53841805 A US 53841805A US 7481275 B2 US7481275 B2 US 7481275B2
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gas
synthesis
unit
oxygen
plant
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US20060272813A1 (en
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Ola Olsvik
Erling Rytter
Jostein Sogge
Jan Age Stensen
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Equinor Energy AS
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/36—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using oxygen or mixtures containing oxygen as gasifying agents
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/38—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts
    • C01B3/384—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts the catalyst being continuously externally heated
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/40—Separation associated with re-injection of separated materials
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521—Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04527—Integration with an oxygen consuming unit, e.g. glass facility, waste incineration or oxygen based processes in general
    • F25J3/04539—Integration with an oxygen consuming unit, e.g. glass facility, waste incineration or oxygen based processes in general for the H2/CO synthesis by partial oxidation or oxygen consuming reforming processes of fuels
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521—Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04563—Integration with a nitrogen consuming unit, e.g. for purging, inerting, cooling or heating
    • F25J3/04569—Integration with a nitrogen consuming unit, e.g. for purging, inerting, cooling or heating for enhanced or tertiary oil recovery
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521—Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04563—Integration with a nitrogen consuming unit, e.g. for purging, inerting, cooling or heating
    • F25J3/04575—Integration with a nitrogen consuming unit, e.g. for purging, inerting, cooling or heating for a gas expansion plant, e.g. dilution of the combustion gas in a gas turbine
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521—Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04593—The air gas consuming unit is also fed by an air stream
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0205—Processes for making hydrogen or synthesis gas containing a reforming step
    • C01B2203/0227—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step
    • C01B2203/0233—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step the reforming step being a steam reforming step
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/061—Methanol production
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/062—Hydrocarbon production, e.g. Fischer-Tropsch process
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C01B2203/0816—Heating by flames

Definitions

  • the present invention regards the use of natural gas in the development of industry and oil fields.
  • the invention regards a method and a plant for integrated production of synthesis gas for synthesis of higher hydrocarbons or oxygenated hydrocarbons and gas for injection into an oil reservoir.
  • Natural gas as such may be injected into fields where the gas does not have a net value that exceeds the excess profits of increasing the oil recovery in the field.
  • An oil field contains hydrocarbon liquids (oil), associated gas and water.
  • Cleaning waste gas from the combustion on the production installation can provide CO 2 for injection into oil reservoirs.
  • CO 2 cleaned from the waste gas from gas power plants be re-injected by laying a pipeline from a gas power plant to the production installation for hydrocarbons.
  • N 2 may be produced together with O 2 in a so-called air separation unit (ASU).
  • ASU air separation unit
  • the oxygen-depleted stream is used for injection into a “solid carbonaceous formation” for improved recovery of methane, and at least a part of the oxygen-enriched stream is used for reaction with a reactant stream containing at least one oxidizable reactant.
  • processes are steelmaking operations, production of non-ferrous metals, chemical oxidation processes and production of synthesis gas for Fischer-Tropsch synthesis of higher hydrocarbons from natural gas.
  • the oxygen-depleted stream has a nitrogen-to-oxygen volume ratio of 9:1 to 99:1. A too-high ratio may lead to the formation of an explosive gas.
  • An oxygen-depleted gas, e.g. nitrogen, for injection into an oil field to enhance the production preferably includes less than 0.1% oxygen.
  • U.S. Pat. No. 4,344,486 relates to a method for enhanced oil recovery where a mixture of carbon dioxide and contaminants comprising hydrocarbon, hydrogen sulfide or mixtures thereof is recovered from an underground formation; the recovered mixture is combusted with an oxygen-enriched stream to form a concentrated carbon dioxide stream where at least a part of the carbon dioxide stream is injected into an underground formation to enhance recovery of liquid hydrocarbon. It is also described to use nitrogen from an air separation unit for injection, together with the concentrated carbon dioxide stream.
  • Natural gas may also be used as feed for a number of processes such as the production of methanol, di-methyl ether or other oxygenated hydrocarbons, and/or synthetic fuel/propellant. This can take place in accordance with known processes such as described in PCT/NO00/00404.
  • Syngas is a mixture of CO, CO 2 , H 2 and water vapor and some non-reacted natural gas.
  • the syngas is used in various synthesis reactions, such as for the production of methanol and other oxygenated hydrocarbons, heavier hydrocarbons and ammonia.
  • the oxygen produced in an air separation unit in such a plant is typically >95% pure oxygen, while the nitrogen will be relatively impure nitrogen that is not suitable for other applications, and is therefore released to the atmosphere.
  • a process for preparation of higher hydrocarbons and for enhancing the production of crude oil from an underground formation is described in Canadian Patent No. 1,250,863.
  • the off-gas from the synthesis plant is oxidized into mainly CO 2 and H 2 O before it is injected into the underground formation.
  • the presence of nitrogen is avoided by using oxygen from an air separation unit for all oxygen-demanding processes.
  • a method for increasing oil recovery from an oil reservoir in which method gas is injected into the reservoir comprising the steps of:
  • waste gas from the synthesis unit is sent to a CO 2 recovery unit including a CO shift converter, where CO 2 is removed and injected into the reservoir and the remaining hydrogen-rich stream is used for other purposes.
  • a CO 2 recovery unit including a CO shift converter
  • a plant for providing gas for down-hole injection for pressure support in an oil reservoir for recovery of hydrocarbons and production of oxygenated hydrocarbons or higher hydrocarbons from natural gas comprising:
  • the plant additionally comprises a tail gas treatment unit for removing CO by a shift reaction and separation of hydrogen from the remaining tail gas.
  • a tail gas treatment unit for removing CO by a shift reaction and separation of hydrogen from the remaining tail gas.
  • the plant comprises means for transferring the remaining tail gas from the tail gas treatment unit to the means for injecting gas.
  • the synthesis unit preferably comprises one or more once-through Fischer-Tropsch units for synthesis of higher hydrocarbons.
  • the plant comprises means for introducing all or parts of the separated hydrogen from the tail gas treatment unit into the Fischer-Tropsch loop to adjust the H 2 /CO ratio to a desired level.
  • the co-producing air separation unit By combining a plant for production of high-purity nitrogen with the production of oxygen, the co-producing air separation unit only becomes 10-20% more expensive than an air separation unit that only produces high-purity nitrogen for injection into oil fields. This allows significant cost savings, both for production of synthesis products such as methanol and synthetic fuel, and for oil field injection.
  • EOR injection fluids or gases are or can be produced as part of the operation of a GTL plant.
  • the possibilities are at least:
  • FIG. 1 shows a schematic diagram of an embodiment of the present invention
  • FIG. 2 shows a schematic diagram of alterative options for the present invention
  • FIG. 3 shows an alternative embodiment of the present invention
  • FIG. 4 shows an alternative embodiment of the present invention.
  • FIG. 5 is an illustration of the economical impact of the integrated process according to the present invention.
  • FIG. 1 is a schematic diagram showing the principal features of a preferred embodiment of the present invention.
  • Air is drawn in through an air intake 1 to an air separation unit 2 , where it is separated into the main components nitrogen and oxygen.
  • the air separation unit differs from traditional air separation units used for production of oxygen to reformers or for production of nitrogen for injection into an oil well, in that it produces both nitrogen and oxygen with a high purity.
  • the produced nitrogen typically has a purity of >99.9%, while the oxygen typically has a purity of 98-99.5%.
  • the nitrogen is passed through line 3 to a compressor 4 where it is compressed to the desired pressure, e.g. of the order of 50-400 bar. From the compressor 4 , the compressed nitrogen stream is passed through a line 5 to a plant 6 for injection of gas into a field, a so-called EOR unit (“Enhanced Oil Recovery”).
  • EOR unit Enhanced Oil Recovery
  • the oxygen is passed through a line 7 to a synthesis gas production unit, a so-called reformer 8 .
  • Natural gas is fed to the plant through a gas inlet 9 .
  • a gas inlet 9 Prior to the natural gas being sent into line 11 to the reformer for production of synthesis gas, it is treated in a pre-treatment unit 10 in which sulfur compounds are removed in a conventional manner. Steam is then saturated into the gas and/or added directly to the gas. The saturation may take place by means of a so-called saturator.
  • the gas is also treated in a so-called pre-reformer in order to convert all heavier hydrocarbons (C2+) to methane, CO and CO2 before the gas is sent into the reformer 8 .
  • Reaction 1 in the reforming reactor is highly endothermic, and the heat required for the reaction may either be added through external heating, such as in a steam reformer, or through a combination with internal partial oxidation according to reaction 2, such as in an autothermal reformer.
  • NG natural gas
  • a conventional steam reformer consists of a large number of reactor tubes in a combustion chamber.
  • Conventional steam reformers are operated in a pressure range from approximately 15 to 40 bar.
  • the outlet temperature for such a reformer can get up to 950° C.
  • the heat required to drive the reaction is added by means of external heating in the combustion chamber in which the reformer tubes are installed.
  • the reformer may be top, bottom or terrace fared.
  • the heat can also be transferred to the reaction by means of convective heat as in a heat exchanger reactor.
  • the ratio between steam and carbon in the feed gas is from 1.6 to 4.
  • the composition of the synthesis gas may as an example be expressed in stoichiometric numbers (SN ⁇ (H 2 —CO 2 )/(CO 2 +CO)).
  • the stoichiometric number for the product stream from the steam reformer is approximately 3 when the natural gas contains pure methane.
  • a typical synthesis gas from a conventional steam reformer contains approximately 3-volume % methane on dry gas basis.
  • an autothermal reformer the synthesis gas production mainly takes place through reactions 1 and 2, such that the heat required for reaction 1 is generated internally via reaction 2.
  • natural gas methane
  • oxygen-containing gas such as air.
  • the temperature of the combustion chamber can get up to over 2000° C.
  • the reactions are brought to an equilibrium across a catalyst before the gases leave the reformer at a temperature of approximately 1000° C.
  • the stoichiometric number, SN, for the product stream from an ATR is approximately 1.6-1.8.
  • the pressure may typically be around 30-40 bar, but a significantly higher pressure has also been proposed, such as in the range of 40-120 bar.
  • the steam/carbon ratio may vary with the intended application, from 0.2 to 2.5.
  • An alternative autothermal reformer makes use of a concept called partial oxidation (POX).
  • POX partial oxidation
  • Such a reformer does not contain any catalyst for accelerating the reactions, and will therefore generally have a higher outlet temperature than an ATR.
  • Natural gas reforming may also take place through combined reforming (CR), where the reformer section consists of a SR and an ATR.
  • CR combined reforming
  • a combination of SR and ATR allows the composition exiting the reformer section to be adjusted by regulating the duties of the two reformers.
  • SR will in CR be operated under somewhat milder conditions than in the case of normal SR, i.e. at a lower temperature. This results in a higher methane slippage in the outlet gas from the reformer. This methane content is converted in the subsequent ATR.
  • the ratio between steam and carbon in the gas feed will, for such a reformer, lie in the range 1.2 to 2.4, with a stoichiometric number, SN, of around 2 or slightly on the high side of 2.
  • the desired composition of the synthesis gas will depend on the process for which it is to form the raw material.
  • the optimum stoichiometric number for methanol synthesis is around 2.05, while the desired stoichiometric number for production of synthetic fuel often lies in the range 1.6 to 1.9, as a higher stoichiometric number gives a greater yield of lighter hydrocarbons than desirable.
  • the synthesis gas After reforming, the synthesis gas is cooled by being heat exchanged with water to give steam. Upon further cooling, water is condensed and separated from the synthesis gas before the synthesis gas is sent via a line 12 to a synthesis unit 15 .
  • the synthesis unit 15 may for instance be a synthesis unit for production of synthetic fuel (heavier hydrocarbons), comprising a so-called Fischer-Tropsch reactor (F-T reactor), or a synthesis unit for production of oxygenated hydrocarbons such as methanol and di-methyl ether.
  • synthetic fuel hereinvier hydrocarbons
  • F-T reactor Fischer-Tropsch reactor
  • oxygenated hydrocarbons such as methanol and di-methyl ether
  • n CO+2 n H 2 [—CH 2 —] n +n H 2 O
  • the reaction is highly exothermic.
  • the Fischer-Tropsch synthesis is well known and is described e.g. in PCT/NO00/00404.
  • Both of the above synthesis units comprise a number of components per se, and both processes normally include internal recycling of non-reacted synthesis gas in order to increase the carbon efficiency of the process.
  • the product from the synthesis unit 15 is extracted through a product outlet 16 for further treatment.
  • Non-reacted synthesis gas and inert gas that collects in the loop can be removed from the synthesis unit 15 through line 17 .
  • This gas will in the following description be denoted the waste gas from the synthesis unit.
  • the amount and composition of the waste gas from the synthesis unit depends on the released methane in the synthesis gas from the reformer section, as well as selected process parameters in the synthesis unit.
  • the volume of waste gas from the synthesis unit may be small. In this case, this gas may be released or combusted prior to being released in order to avoid emissions of hydrocarbons and CO.
  • the waste gas from the synthesis unit may alternatively be further passed to a CO shift converter 18 in which non-converted CO is converted according to the following reaction equation: CO+H 2 O->CO 2 +H 2 in order to make it easier to separate out the carbon contents of the gas.
  • the gas may if required be led through a line 19 to a CO 2 recovery unit 20 in which CO 2 is separated from the other constituents of the gas.
  • CO 2 may be separated out by means of an absorption process, e.g. by means of an amine, a cryogenic process or possibly by means of membranes.
  • CO 2 is led via a line 21 , a compressor 28 and further via a line 29 to EOR unit 6 .
  • the gas that was separated from CO 2 in the recovery unit 20 is passed further through a line 22 to other uses in a unit 23 .
  • the unit 23 may be a furnace in which the gas is combusted under the addition of air, oxygen or oxygen-enriched air and provides heat for a heat-requiring process.
  • the gas may be burnt in a gas turbine alone or as additional heating.
  • hydrogen may be separated from the gas before it is burnt or alternatively released. Hydrogen may here be used for hydrogen-requiring processes such as e.g. upgrading of oil by sweetening (removal of sulfur), for saturation of unsaturated hydrocarbons and hydrocracking or for use in fuel cells.
  • FIG. 2 shows alternative and optional embodiments of a plant according to the present invention.
  • the figure is based on the same principal units as FIG. 1 , but some optional, and in some cases preferred, additional units besides bypass lines and feedback lines, have been added in order to ensure the highest possible conversion or in order to adjust the composition of the gas.
  • a CO 2 recovery unit 13 may be interposed between the reformer 8 and the synthesis unit 15 . By so doing, a desired amount of CO 2 can be removed from the synthesis gas and passed through a line 27 to the compressor 28 , where it is brought together with CO 2 from line 21 . This can be used as a means of changing the stoichiometric number of the synthesis gas so as to give it an optimum composition.
  • the synthesis unit 15 is a synthesis unit for production of synthetic fuel, synfuel
  • the H 2 /CO ratio of the synthesis gas may be adjusted to the desired value, i.e. around 2.0 or just below 2.0, and the CO yield and thereby also synthetic fuel yield may be increased by the high content of CO 2 in the recycling gas, suppressing further conversion of CO to CO 2 through the shift reaction in the autothermal reformer.
  • CO 2 is to be considered an inert gas in the F-T synthesis.
  • the reformer 8 produces more synthesis gas than can be converted in the synthesis unit 15 , some of the synthesis gas may be led from a line 14 running between the CO 2 recovery unit 13 and the synthesis unit 15 , and around the synthesis unit 15 in a bypass line 25 . This may also be desirable if there is a wish to produce more heat or power in a furnace or gas turbine 23 .
  • the units 13 and 20 for separating CO 2 from the remainder of the gas are known units.
  • the reformer 8 being supplied with pure oxygen instead of air, the volume of gas to be treated becomes considerably smaller.
  • the separation in the units 13 , 20 may take place in a known manner by means of semi-permeable membranes or by absorption with subsequent desorption, e.g. in an amine solution.
  • the air separation unit 2 is preferably a plant based on cryogenic distillation, however it is also possible to use plants based on pressure swing adsorption or membranes or a combination of these technologies.
  • FIG. 3 shows a third embodiment in which non-converted synthesis gas from the synthesis unit 15 is combusted with pure oxygen in a furnace or gas turbine 30 .
  • Units having the same reference numbers as in FIG. 1 or 2 indicate similar units with a similar functionality.
  • Oxygen is passed from line 7 through a line 40 and mixed with CO 2 in a line 41 , from where it passes into furnace or gas turbine 30 .
  • the waste gas from the furnace or gas turbine 30 goes via a line 31 to a catalytic secondary combustion chamber 32 in which the remaining fuel in the form of CO, H 2 or non-combusted hydrocarbon is converted catalytically.
  • the products of combustion from the secondary combustion chamber 32 containing water and CO2 are passed via-a line 33 to a condensation unit 34 , where water is condensed out and led out through a line 35 , while CO 2 is passed to the EOR unit 6 via a line 36 .
  • CO 2 may be led from line 36 via a line 37 to a compressor 38 .
  • some compressed CO 2 must be recycled via line 41 to the furnace or gas turbine 30 in order to maintain the combustion temperature in this below a given maximum temperature.
  • natural gas from line 11 may be led via a line 42 directly to the furnace or gas turbine 30 .
  • the combustion in the furnace or gas turbine 30 takes place at an elevated pressure, such as from 2 to 100 bar, more preferably from 20 to 40 bar. Having the combustion take place with pressurized oxygen facilitates the separation of CO 2 in the following condensation unit 34 .
  • FIG. 4 illustrates a fourth embodiment of the present invention wherein the synthesis unit is a once-through Fischer-Tropsch system for synthesis of higher hydrocarbons from natural gas.
  • Units having the same reference numbers as in FIG. 1 , 2 and/or 3 indicate units having the same functionality.
  • Natural gas from the gas inlet 9 is saturated and pre-reformed in the pre-treatment unit 10 .
  • Steam for the pre-treatment is added through a steam line 50 .
  • the pre-treated natural gas is passed from the pre-treatment unit 10 to the reformer 8 , for production of syngas, through line 11 .
  • Oxygen from the air separation unit (ASU) 2 is introduced into the reformer 8 through line 7 .
  • Nitrogen from the ASU 2 is passed through line 3 to the plant for injection (EOR) 6 .
  • the reformer 8 is a traditional steam methane reformer (SMR) or an autothermal reformer (ATR) and may include one or more units for syngas production and/or separation of the produced syngas.
  • Syngas produced in the reformer 8 is passed through line 12 to a syngas cool-down unit 52 . All or apart of the flue gas from the reformer 8 , mainly comprising CO 2 and H 2 O, may be separated from the syngas and led to the EOR 6 through a line 51 .
  • the line 51 is dotted to indicate that the line 51 is not obligatory. If the reformer 8 is a ATR unit there will be no flue gas and no line 51 .
  • syngas cool-down unit 52 water is introduced through line 53 and steam is withdrawn through a line 54 .
  • the steam in line 54 may be led to the EOR for injection into the oil reservoir. If some or all of the steam in line 54 is not needed for injection, some or all of the steam in line 54 may be used for other purposes. Some of the steam may be transferred to line 50 and be introduced to the pre-treatment unit 10 .
  • the steam may be utilized in a not shown turbine to generate power for other uses.
  • the cooled-down syngas leaves the cool-down unit 52 through a line 42 and is passed through a membrane unit 43 , where hydrogen is separated from the syngas to give an H 2 /CO ratio that is useful for the further reactions.
  • a not-shown water separation unit may be placed between the cool-down unit 52 and the membrane unit 43 to separate water from the syngas before it is introduced into the membrane unit 43 .
  • the decant water separated from the syngas is led through line 49 to the EOR 6 , and hydrogen is withdrawn through line 48 and can be used as fuel gas or for feed gas desulfurization or hydrotreating/hydrocracking of oils fractions.
  • the syngas leaving the membrane unit 43 through a line 44 is introduced into a Fischer-Tropsch (FT) synthesis loop 56 for production for higher hydrocarbons.
  • FT Fischer-Tropsch
  • Higher hydrocarbons in the present description are hydrocarbon molecules having three or more carbon atoms, more preferably five or more carbon atoms.
  • Raw higher hydrocarbon product from the FT synthesis loop 56 is withdrawn through a line 57 , and the produced water is withdrawn through a line 58 and passed to the EOR 6 .
  • tail gas mainly comprising CO 2 , lower hydrocarbons, H 2 O, CO and some nitrogen, is withdrawn through a line 62 .
  • the tail gas in line 62 is introduced to a tail gas treatment unit 63 , in which CO is removed by a shift reaction (CO+H 2 O ⁇ CO 2 +H 2 ).
  • the remaining tail gas is split into a hydrogen rich stream that is withdrawn through a line 64 , and a hydrogen poor fraction that is withdrawn through a line 65 .
  • the hydrogen in line 64 may be used for other reactions requiring hydrogen and/or be introduced into the Fischer-Tropsch loop 56 to adjust the H 2 /CO-ratio in the syngas.
  • the remaining tail gas, or the hydrogen-poor fraction, in line 65 may be split into two streams, one in a line 59 that is introduced to the EOR and another stream in a line 45 that is used as fuel for a power generation unit 46 .
  • the tail gas introduced into the power generation unit 46 is burned in the presence of air or oxygen-enriched air to produce power or heat. Flue gas from the power generation unit 46 is led through a line 47 to the EOR 6 for injection.
  • the great advantage of the present method and plant is that they allow simple and energy efficient operation of the combined plant.
  • the present method also allows a more efficient and financially justifiable method of removing CO 2 from the waste gas from a methanol plant or plant for production of synthetic fuel, for injection, so as to allow the emission of CO 2 to be eliminated or at least reduced considerably.
  • the present invention in its different embodiments, also makes it possible to customize the plant and respectively alter the working conditions according to the specific need and/or variations in economical and technical factors.
  • the air separation unit can deliver 38 400 MTPD N 2 and 6400 MTPD O 2 .
  • This air separation unit requires approximately 115 MW of power, which is delivered in the form of high-pressure steam from the synthesis gas section.
  • the nitrogen is extracted at 3 bar and 0 degrees C.
  • the gas is compressed to 220 bar for injection. Compression requires approximately 304 MW.
  • the oxygen can be fed to an autothermal reformer for production of synthesis gas from natural gas.
  • the process operates with a steam/carbon ratio of 0.6.
  • the temperature and pressure at the outlet from the ATR is 1030 degrees Celsius and 45 bar, respectively. See Table 1 for the natural gas composition. Note, all compositions are given on a dry basis, i.e. without water.
  • Synthesis gas is compressed to 90 bar and mixed with recycled hydrogen in order to achieve a stoichiometric number of 2.56 prior to the methanol synthesis. 10000 MTPD of methanol is produced.
  • the waste gas from the synthesis unit, the purge gas, is sent to CO shift conversion 35 t/h of steam is added in order to convert 85% of CO to CO 2 in a low temperature shift converter (200 degrees Celsius).
  • CO 2 in converted purge gas (equivalent to 1700 MTPD CO 2 ) is recovered in an MDEA process. Due to a high concentration of CO 2 in the natural gas feed, this example includes CO 2 removal prior to ATR (equivalent to 800 MTPD CO 2 ), so that the total amount of recovered CO 2 is 2500 MTPD. Recovered CO 2 is compressed to 220 bar, and may if so desired be mixed with nitrogen prior to injection into the reservoir. CO 2 will then constitute around 6.2 weight % of the total injection gas. CO 2 constitutes a relatively small share of the total injectable gas. The cleaning of this may end up being so costly that it will only be done if required by the authorities.
  • the remaining purge gas is used in fired heaters for superheating of steam in power production and preheating of natural gas feeds.
  • the requirement for added power is approximately 280 MW.
  • a simulation on a plant as illustrated in FIG. 4 was performed.
  • 367 000 Sm 3 /hr natural gas from line 9 was mixed with 183 t/h steam from line 50 in order to reach steam to carbon ratio of 0.6.
  • the mixture was preheated to 600° C. and fed to an auto-thermal reformer (ATR) 8.275 t/hr oxygen (6600 MTPD) was introduced into the ATR 8 from the line 7 .
  • the outlet temperature from the ATR 8 was 1030° C.
  • the amount of oxygen consumed in the ATR corresponds to a co-production of N 2 of 39600 MTPD.
  • the syngas leaving the ATR 8 through line 12 which is in equilibrium and at a temperature of around 1030° C., is cooled to about 350° C. with evaporating water in the syngas cool down unit 52 producing about 830 t/h saturated 110 bar steam that is withdrawn in line 54 .
  • the steam in line 54 may be utilized for EOR as illustrated in FIG. 4 , or in turbines to generate power.
  • decant water is removed and about 60 000 Sm 3 /hr hydrogen (hydrogen purity of 90%) is separated in the membrane unit 43 before the syngas is fed to the Fischer-Tropsch loop 56 .
  • the decant water is withdrawn through line 49 and may be used for EOR.
  • the separated hydrogen is withdrawn through line 48 and is introduced into line 64 or is being used for any process, either connected to the plant in question or another plant requiring hydrogen.
  • the Fischer-Tropsch loop produces 233 t/h gas that is withdrawn through line 65 , 138 t/h syncrude (long paraffin chains) that is withdrawn through line 57 and 198 t/h water that is withdrawn through line 58 .
  • the syncrude must be farther processed in a way known by the skilled man in the art, by a not shown hydrotreater, hydrocracker and/or solvent de-waxing unit in order to give desired products (LPG, naphtha, diesel and/or lube oils).
  • the water from the Fischer-Tropsch loop that is withdrawn in line 58 contains dissolved impurities (mainly alcohols) and may be transferred to the EOR 6 and be injected into the oil field.
  • impurities mainly alcohols
  • the gas may be shifted with a low-temperature copper catalyst to convert about 86% of the CO into CO 2 .
  • a CO 2 recovery of 95% will then imply that 180 t/hr CO 2 is available for EOR purpose from the gas in line 65 .
  • the composition of the gas in line 65 is given in Table 4.
  • the benefit of using the nitrogen byproduct produced by the air-separation unit (ASU) of a GTL plant, for enhanced oil recovery (EOR), may be evaluated by analyzing the potential impact on the gas price of the GTL plant.
  • the natural gas price is without any doubt a major factor determining the profitability of such a plant, and a credit will be achieved for selling nitrogen.
  • Nitrogen and methane have roughly the same properties in EOR operations, essentially as pressure support. At the outset, we may therefore assume that the value of the neat nitrogen is equivalent to the gas price. We then will have:
  • P Natural gas price in the area of the GTL facility.
  • P Net ( GTL ) aP ⁇ bcP (Area gas price ⁇ credit for nitrogen sale) where the coefficients are:
  • line II indicates that there is a huge potential if a relevant EOR case can be found.
  • Line III shows that such an integration project will be robust against significant added investments.
  • line IV illustrates the point that even by passing half of the savings in the gas price over to the EOR operator, the net GTL gas price actually will be lower for a high gas price in the area.
  • the vertical arrows indicate that the added value for both plants is 1.085 USD/MMbtu of GTL feed gas.

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WO2004055323A1 (fr) 2004-07-01
EG24539A (en) 2009-09-07
EA200500813A1 (ru) 2006-02-24
AU2003288799A1 (en) 2004-07-09
NO20026021D0 (no) 2002-12-13
CA2509945A1 (fr) 2004-07-01
US20060272813A1 (en) 2006-12-07
CA2509945C (fr) 2011-10-11
MXPA05006313A (es) 2005-08-26
EA007208B1 (ru) 2006-08-25
BR0317285A (pt) 2005-11-08

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